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The U.S. data-center power crunch is not just a question of building more power plants. Electricity demand is rising, but transmission constraints and slow grid connections can keep both new generators and large customers from getting power where it is needed. Utilities, energy companies, grid operators and regulators are responding with new generation and storage, grid upgrades, and revised connection rules. Those efforts are substantial, but announced capacity is not the same as electricity already delivered.
What is causing the data-center power crunch?
Data centers add large, concentrated electricity loads. When a facility seeks service in a region with limited transmission capacity, the challenge is not necessarily that the country lacks enough generation in total. It may be that power cannot be moved into the area, that a new generator cannot connect quickly, or that the local grid needs upgrades before it can serve the load reliably.
The U.S. Department of Energy’s July 9, 2026 draft National Transmission Needs Study identifies pressing additional transmission needs related to data centers, manufacturing, other large industrial loads and electrification. It points to capacity constraints and congestion, and says transmission is needed for reliability, new generation and load interconnections, and congestion relief. The study is intended to inform planning; it does not choose specific projects or solutions. Its public comment period closed September 8, 2026.
Interconnection queues show the scale of the challenge beyond the United States. The International Energy Agency reported in 2026 that more than 2,500 GW of generation, storage and large-load projects were waiting in grid connection queues worldwide. That global total is not a count of data centers or U.S. projects, but it illustrates why adding supply alone may not resolve connection bottlenecks.
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How quickly is electricity demand growing?
The U.S. Energy Information Administration’s September 9, 2026 Short-Term Energy Outlook forecasts U.S. electricity sales of 4,135 billion kWh in 2026 and 4,211 billion kWh in 2027. These are forecasts, not measured results. EIA attributes expected record electricity consumption partly to data-center development and increased manufacturing; it forecasts commercial electricity sales to grow 3.3% in 2026 and 2.7% in 2027.
The longer-term outlook is a range of possible futures rather than one prediction. In its April 2026 Annual Energy Outlook, EIA says U.S. electricity demand grew by an average of 2.1% annually over the prior five years and projects average annual growth of 0.9% to 1.6% through 2050 across its scenarios. The scenarios show installed electric generating capacity rising 50% to 90% by 2050. EIA Administrator Tristan Abbey described AEO2026 as “a product suite for alternative futures analysis, not a set of predictions.”
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What is the industry doing to get more usable power?
The response combines new infrastructure with measures that could help the existing grid carry more electricity. The options differ in timing, location, reliability, cost allocation and emissions; none is a universal fix.
| Approach | What it can address | What to keep in mind |
|---|---|---|
| New generation and storage | Adds supply near a large load or to the wider grid; storage can shift some electricity across time. | Projects must be built, connected and able to serve the constrained location. Nameplate capacity alone does not show dependable output, storage duration or annual energy delivered. |
| Transmission construction and upgrades | Moves electricity between regions and can relieve local constraints while enabling new generation and loads to connect. | Major projects require planning, permitting and construction; the DOE needs study identifies needs but does not select solutions. |
| Grid-enhancing technologies | Dynamic line ratings, power-flow controls, reconductoring and voltage uprating can increase or redirect usable capacity on existing networks. | Benefits depend on local grid conditions and implementation; they do not replace every major transmission build. |
| Flexible or non-firm connections | Can let some customers or projects connect sooner if their use of constrained grid capacity can be limited when necessary. | Customers must accept possible curtailment, and the value depends on when and how often constraints occur. |
The IEA estimates that annual global grid investment would need to rise by roughly 50% by 2030 from about USD 400 billion to meet forecast electricity demand. It also estimates that flexible non-firm connection agreements could enable around 750–900 GW of advanced-stage queued projects worldwide, while grid-enhancing technologies and larger upgrades could unlock another 450–700 GW. These are estimates of potential capacity, not completed projects or guaranteed U.S. outcomes.
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In September 2026, the U.S. Department of Energy described grid projects using tools such as real-time line monitoring and equipment that redirects power away from congested paths. The Associated Press reported DOE’s expectation that 31 projects across 26 states would add more than 23 GW of capacity. That figure is an agency expectation reported by AP, not a measurement of capacity already delivered.
What do announced generation and storage projects show?
Paducah, Kentucky
DOE announced a proposed data-center campus at the former Paducah site, with planned 2 GW of new grid-connected gas generation, up to 2.6 GW of battery storage, transmission upgrades, and a planned 1.8 GW data-center campus. DOE said electricity beyond campus needs could flow to the regional grid. These are development plans, not operating assets. The project announcement presents benefits to ratepayers as an intention; it does not independently establish that those benefits will occur.
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Portsmouth, Ohio
DOE announced a partnership under which SB Energy planned 10 GW of generation associated with a 10 GW data-center development. The planned generation includes 9.2 GW of natural gas. The announcement does not establish a construction schedule, completed capacity or a date when the facilities will supply electricity.
Regional resource examples
MISO’s September 2026 fifth ERAS cycle announcement included a 400 MW solar project paired with 400 MW of storage in Arkansas and 400 MW of gas generation in Indiana. The examples show a mix of resources in a regional project process; they do not establish that the projects are online or specifically assigned to data-center demand.
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How are connection rules changing?
On June 18, 2026, the Federal Energy Regulatory Commission issued show-cause orders to the six RTOs and ISOs under its jurisdiction: PJM, MISO, SPP, CAISO, ISO New England and NYISO. The orders require each organization to justify or revise relevant rules for large loads such as data centers and manufacturing facilities. They address matters including adequate generation, protections against shifting costs to other customers, and existing agreements.
The orders recognize that procedures and regional needs differ. SPP, for example, already has expedited assessment processes for high-impact large loads. FERC regulates the named regional grid organizations, but states retain important authority over generation selection, siting and permitting, and retail rates and terms. As a result, connection rules and cost outcomes can vary by location.
Will new generation alone solve the problem?
No single resource type or project announcement establishes a nationwide solution. EIA’s long-term scenarios describe a wide range of capacity growth, while its near-term outlook describes different trends for gas, coal, solar and wind. Local deliverability matters as much as total capacity: electricity needs a viable connection and transmission path to reach the data center at the time it is needed.
For a proposed project, the practical questions are whether it has secured the necessary approvals and grid connection, when it could operate, how reliably it can supply power, and who pays for generation and network upgrades. The available announcements do not establish final costs, completion dates or the share of net capacity that will serve a campus versus the wider grid. Those details will determine how much each proposal eases a regional constraint.
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Quick Recap
What should readers watch next?
- Transmission planning: whether identified needs turn into funded, permitted projects that can relieve the specific regional constraints affecting large loads.
- Grid utilization: whether monitoring, power-flow controls and other upgrades add usable capacity on constrained paths while longer builds proceed.
- Connection terms: how regional rules allocate upgrade costs, protect reliability and define any curtailment obligations for large customers.
- Project delivery: whether announced generation and storage proposals move through approvals, construction and interconnection to become operating resources.
- Regional resource mix: how utilities and grid operators balance reliability, flexibility, emissions goals, permitting and customer costs in their own systems.
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